Apparatus and methods for drilling

ABSTRACT

A drilling method in which a rotary drill bit is mounted on a tubular drillstring extending through a bore comprises: drilling through a formation containing fluid at a predetermined pressure; circulating drilling fluid down through the drill string to exit the string at or adjacent the bit, and then upwards through an annulus between the string and bore wall; and adding energy to the drilling fluid in the annulus location above the formation. The addition of energy to the fluid in the annulus has the effect that the pressure of the drilling fluid above the formation may be higher than the pressure of the drilling fluid in communication with the formation and that predetermined differential may be created between the pressure of the formation fluid and the pressure of the drilling fluid in communication with the formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is the National Stage of International Application No.PCT/GB00/00642, filed on Feb. 25, 2000 and published under PCT Article21(2) in English, and claims priority of United Kingdom Application No.9904380.4 filed on Feb. 25, 1999. The aforementioned applications areherein incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to a drilling method, and to a drillingapparatus. Embodiments of the invention relate to a drilling method andapparatus where the effective circulating density (ECD) of drillingfluid (or drilling “mud”) in communication with a hydrocarbon-bearingformation is lower than would be the case in a conventional drillingoperation. The invention also relates to an apparatus for reducing thebuildup of drill cuttings or other solids in a borehole during adrilling operation; and to a method of performing underbalance drilling.

2. Description of the Related Art

When drilling boreholes for hydrocarbon extraction, it is commonpractice to circulate drilling fluid or “mud” downhole: drilling mud ispumped from surface down a tubular drillstring to the drill bit, wherethe mud leaves the drillstring through jetting ports and returns tosurface via the annulus between the drillstring and the bore wall. Themud lubricates and cools the drill bit, supports the walls of theunlined bore, and carries dislodged rock particles or drill cuttingsaway from the drill bit and to the surface.

In recent years the deviation, depth and length of wells has increased,and during drilling the mud may be circulated through a bore severalkilometres long. Pressure losses are induced in the mud as it flowsthrough the drillstring, downhole motors, jetting ports, and then passesback to the surface through the annulus and around stabilisers,centralisers and the like. This adds to natural friction associatedpressure loss as experienced by any flowing fluid.

Similarly, the pressure of the drilling mud at the drill bit and, mostimportantly, around the hydrocarbon-bearing formation, has tended torise as well depth, length and deviation increase; during circulation,the pressure across the formation is the sum of the hydrostatic pressurerelating to the height and density of the column of mud above theformation, and the additional pressure required to overcome the flowresistance experienced as the mud returns to surface through theannulus. Of course the mud pressure at the bit must also be sufficientto ensure that the mud flowrate through the annulus maintains theentrainment of the drill cuttings.

The mud pressure in a bore is often expressed in terms of the effectivecirculating density (ECD), which is represented as the ratio between theweight or pressure of mud and the weight of a corresponding column ofwater. Thus, the hydrostatic pressure or ECD at a drill bit may bearound I.05SG,; whereas during circulation the mud pressure, or ECD, maybe as high as I.55SG.

It is now the case that the ECD of the drilling mud at the lower end ofthe bore where the bore intersects the hydrocarbon-bearing formations isplacing a limit on the length and depth of bores which may be drilledand reservoirs accessed. In addition to mechanical considerations, suchas top drive torque ratings and drill pipe strength, the increase in ECDat the formation may reach a level where the mud damages the formation,and in particular reduces the productivity of the formation. Duringdrilling it is usually preferred that the mud pressure is higher thanthe fluid pressure in the hydrocarbon-bearing formation, such that theformation fluid does not flow into the bore. However, if the pressuredifferential exceeds a certain level, known as the fracture gradient,the mud will fracture the formation and begin to flow into theformation. In addition to loss of drilling fluid, fracturing alsoaffects the production capabilities of a formation. Attempts have beenmade to minimise the effects of fracturing by injecting materials andcompounds into bore to plug the pores in the formation. However, thisincreases drilling costs, is often of limited effectiveness, and tendsto reduce the production capabilities of the formation.

High mud pressure also has a number of undesirable effects on drillingefficiency. In deviated bores the drillstring may lie in contact withthe bore wall, and if the bore intersects a lower pressure formation thefluid pressure acting on the remainder of the string will tend to pushthe string against the bore wall, significantly increasing drag on thestring; this may result in what is known as “differential sticking”.

It has also been suggested that high mud pressure at the bit reducesdrilling efficiency, and this problem has been addressed in U.S. Pat.No. 4,049,066 (Richey) and U.S. Pat. No. 4,744,426 (Reed), thedisclosures of which are incorporated herein by reference. Bothdocuments disclose the provision of pump or fan arrangements in theannulus rearwardly of the bit, driven by mud passing through thedrillstring, which reduces mud pressure at the bit. It is suggested thatthe disclosed arrangements improve jetting and the uplift of cuttings.

Another method of reducing the mud pressure at the bit is to improvedrillstring design to minimise pressure losses in the annulus, and U.S.Pat. No. 4,823,891 (Hommani et al) discloses a stabiliser configurationwhich aims to minimise annulus pressure losses, and thus allow a desiredmud flow to be achieved with lower initial mud pressure.

It is also known to aerate drilling mud, for example by addition ofnitrogen gas, however the apparatus by necessary to implement thisprocedure is relatively expensive, cuttings suspension is poor, and thecirculation of two phase fluids is problematic. The presence of lowdensity gas in the mud may also make it difficult to “kill” a well inthe event of an uncontrolled influx of hydrocarbon fluids into thewellbore.

It is among the objects of embodiments of the present invention toobviate or alleviate these and other difficulties associated withdrilling operations.

SUMMARY OF THE INVENTION

According to the present invention there is provided a drilling methodin which a drill bit is mounted on a tubular drill string extendingthrough a bore, the method comprising:

drilling a bore which extends through a formation containing fluid at apredetermined pressure;

circulating drilling fluid down through the drill string to exit thestring at or adjacent the bit, and then upwards through an annulusbetween the string and bore wall; and

adding energy to the drilling fluid in the annulus at a location abovesaid formation such that the pressure of the drilling fluid above saidlocation is higher than the pressure of the drilling fluid below saidlocation and there is a predetermined differential between the pressureof the formation fluid and the pressure of the drilling fluid incommunication with the formation.

The invention also relates to apparatus for use in implementing thismethod.

The method of the present invention allows the pressure of the drillingfluid in communication with the formation, typically ahydrocarbon-bearing formation, to be maintained at a relatively lowlevel, even in relatively deep or highly deviated bores, while thepressure in the drilling fluid above the formation may be maintained ata higher level to facilitate drilling fluid circulation and cuttingsentrainment.

The differential between the drilling fluid pressure and the formationfluid pressure, which is likely to have been determined by earliersurveys, may be selected such that the drilling fluid pressure is highenough to prevent the formation fluid from flowing into the bore, but isnot so high as to fracture or otherwise damage the formation. In certainembodiments, the pressure differential may be varied during a drillingoperation to accommodate different conditions, for example the initialpressure differential may be controlled to assist in formation of asuitable filter cake. Alternatively, the drilling fluid pressure may beselected to be lower than the formation fluid pressure, that is theinvention may be utilised to carry out “underbalance” drilling; in thiscase the returning drilling fluid may carry formation fluid, which maybe separated from the drilling fluid at surface.

Preferably, energy is added to the drilling fluid by at least one pumpor fan arrangement. Most preferably, the pump is driven by the fluidflowing down through the drillstring, such as in the arrangementsdisclosed in U.S. Pat. Nos. 4,049,066 and 4,744,426. Fluid drivendownhole pumps are also produced by Weir Pumps Limited of Cathcart,Glasgow, United Kingdom. The preferred pump form utilises a turbinedrive, that is the fluid is directed through nozzles onto turbine bladeswhich are rotated to drive a suitable impeller acting on the fluid inthe annulus. Such a turbine drive is available, under the TurboMac trademark, from Rotech of Aberdeen, United Kingdom. When using the preferredpump form the initial pump pressure at surface will be relatively high,as energy is taken from the fluid, as it flows down through the string,to drive the pump. Alternatively, in other embodiments it may bepossible for the pump to be driven by a downhole motor, to beelectrically powered, or indeed driven by any suitable means, such asfrom the rotation of the drillstring.

Energy may be added to the drilling fluid in the annulus at a locationadjacent the drill bit, but is more likely to be added at a locationspaced from the drill bit, to allow the bore to be drilled through theformation and still ensure that the higher pressure fluid above saidlocation is spaced from the formation.

In one embodiment of the invention, a proportion of the circulatingdrilling fluid may be permitted to flow directly from the drillstringbore to the annulus above the formation, and such diversion of flow maybe particularly useful in boreholes of varying diameter, the changes indiameter typically being step increases in bore diameter. When the borediameter increases, drilling fluid flow speed in the annulus willnormally decrease, and the additional volume of fluid flowing directlyfrom the drillstring bore into the annulus assists in maintaining flowspeed and cuttings entrainment. This may be achieved by provision of oneor more bypass subs in the string. The bypass subs may be selectivelyoperable to provide fluid bypass only when considered necessary ordesirable.

The drill string may also incorporate means for isolating sections ofone or both of the drill string bore and annulus when there is no fluidcirculation. This is of particular importance when the pressure of thecirculating drilling fluid at the formation is lower than hydrostaticpressure; the isolating means will support the column of fluid above theformation, allowing lower sections of the bore to be maintained atrelatively low pressures. Alternatively, or in addition, the isolatingmeans may serve to prevent fluid flowing from the formation and then upthe bore in underbalance conditions. The isolating means may be in theform of one or more valves, packers, swab cups or the like.

The drillstring may also be provided with means for agitating cuttingsin the annulus, such as the flails disclosed in U.S. Pat. No. 5,651,420(Tibbets et al), the disclosure of which is incorporated herein byreference. Tibbets et al propose mounting flails on elements of thedrillstring, which flails are actuated; by the rotation of the string orthe flow of drilling fluid around the flails. Most preferably however,the agitating means are mounted on a body which is rotatable relative tothe string. The body is preferably driven to rotate by drive meansactuated by the flow of drilling fluid through the string, but may bedriven by other means. This feature may be provided in combination withor separately of the main aspect of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

These and other aspects of the present invention will now be described,by way of example only, with reference to the accompanying drawings, inwhich:

FIG. 1 is a schematic illustration of a conventional wellbore drillingoperation;

FIG. 2 is a graph illustrating the pressure of circulating drilling mudat various points in the wellbore of FIG. 1;

FIG. 3 is a schematic illustration of a wellbore drilling operationaccording to an embodiment of the present invention;

FIG. 4 is a enlarged sectional view of a pump arrangement of FIG. 3; and

FIG. 5 is a graph illustrating the pressure of circulating drilling mudat various points in the wellbore in a drilling operation according toan embodiment of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Reference is first made to FIG. 1 of the drawings, which illustrates aconventional drilling operation. A rotating drill string 12 extendsthrough a borehole 14, and drilling mud is pumped from the surface downthe drill string 12, to exit the string via jetting ports in a drill bit16, and returns to the surface via the annulus 17 between the string 14and the bore hole wall.

Reference is now also made to FIG. 2 of the drawings, which is a sketchgraph of the pressure of the drilling mud at various points in thewellbore 14 as illustrated in FIG. 1. The mud enters the drillstring atsurface at a relatively high pressure P₁, and emerges from the bit 16 ata lower pressure P₂ reflecting the pressure losses resulting from thepassage of the mud through the string 12 and bit 16. The drilling mudreturns to the surface via the annulus 17 and reaches surface at closeto atmospheric pressure P₃.

FIG. 3 of the drawings illustrates a drilling operation in accordancewith an embodiment of a first aspect of the present invention, a drillstring 32 being shown located in a drilled bore intersecting ahydrocarbon-bearing formation 33.

Mounted on the drillstring 32 are two pump assemblies 34, 36 which serveto assist the flow of drilling mud through the annulus, and to allow a,reduction in the ECD at various points in the wellbore, with thelowermost pump 36 being located above the formation 33. One of the pumps34 is shown schematically in FIG. 4 of the drawings, and comprises aturbine motor section 46, such as is available under the TurboMac trademark from Rotech of Aberdeen, United Kingdom, and a pump section 48. Themotor section 46 is arranged to be driven by the flow of mud downholethrough the string bore 44, rotation of the motor section 46 beingtransferred to the pump section 48, which includes vanes 49 extendinginto the annulus 50. The pump vanes are arranged to add energy to themud in the annulus 50, increasing the mud pressure as it passes acrossthe pump section 48.

FIG. 5 is a sketch graph of the pressure of circulating drilling mud ina drilling operation utilizing a single pump assembly 36 as described inFIG. 4, the pump 36 being located in the string such that the pump 36remains above the hydrocarbon-bearing formation during the drillingoperation. The solid line is the same as that of the graph of FIG. 2,and illustrates the circulating mud pressure profile in a comparableconventional wellbore drilling operation. The dashed line illustratesthe effect on the circulating mud pressure resulting from the provisionof a pump assembly 36 in the drillstring, as will be described. Atsurface, the mud pressure must be higher than conventional, shown bypoint 52, and then drops gradually due to pressure losses to point 54,where the fluid in the drill string passes through the pump turbinemotor section 46 and transfers energy to the fluid in the annulus 50, asreflected by the rapid loss of pressure, to point 56. As the mud emergesfrom the drillstring at the drill bit, it is apparent that the pressureor ECD of the mud, at point 58, is lower than would be the case in aconventional drilling operation, despite the higher initial mud pressure52. As the return mud passes up through the annulus 50 it loses pressuregradually until reaching the pump 36, at point 60, whereupon it receivesan energy input in the form of a pressure boost 62, to ensure that themud will flow to the surface with the cuttings entrained in the mudflow. As with a conventional drilling operation, the mud exits thestring at close to atmospheric pressure, at point 64.

The pressure of the fluid in the formation 33 will have been determinedpreviously by surveys, and the location of the pump 36 and the mudpressure between the points 58, 60 is selected such that there is apredetermined pressure differential between the drilling fluid pressureand the formation fluid pressure. In most circumstances, the drillingfluid pressure will be selected to be higher than the formation fluidpressure, to prevent or minimise the flow of formation fluid into thebore, but not so high to cause formation damage, that is at least belowthe fracture gradient.

Thus, it may be seen that the present invention provides a means wherebythe ECD in the section of wellbore intersecting the hydrocarbon-bearingformation may be effectively reduced or controlled to provide apredetermined pressure between the drilling fluid and the formationfluid without the need to reduce the mud pressure elsewhere in thewellbore or impact on cuttings entrainment. This ability to reduce andcontrol the ECD of the drilling mud in communication with thehydrocarbon-bearing formation allows drilling of deeper and longer wellswhile reducing or obviating the occurrence of formation damage, and willreduce or obviate the need for formation pore plugging materials, thusreducing drilling costs and improving formation production.

It will be understood that the foregoing description is for illustrativepurposes only, and that various modifications and improvements may bemade to the apparatus and method herein described, without departingfrom the scope of the invention. For example, the pump assemblies may beelectrically or hydraulically powered, and may only be actuated when thepressure of the drilling mud in communication with the formation risesabove a predetermined pressure; a predetermined detected pressure mayactivate a fluid bypass causing fluid to be directed to drive anappropriate pump assembly.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

What is claimed is:
 1. A drilling method in which a drill bit is mountedon a tubular drill string extending through a bore, the methodcomprising: drilling a bore extending through a formation containingfluid at a predetermined pressure; circulating drilling fluid downthrough the drill string to exit the string at or adjacent the lower endthereof, and then pass upwards through an annulus between the string andbore wall; and adding energy to the drilling fluid in the annulus at alocation above said formation such that the pressure of the drillingfluid above said location is higher than the pressure of the drillingfluid below said location and there is a predetermined differentialbetween the pressure of the formation fluid and the pressure of thedrilling fluid in communication with the formation.
 2. The method ofclaim 1, wherein the differential between the drilling fluid pressureand the formation fluid pressure is selected such that the drillingfluid pressure is high enough to prevent the formation fluid fromflowing into the bore, but is not so high as to damage the formation. 3.The method of claim 1, wherein the pressure of the drilling fluid abovesaid location is higher than the pressure of the drilling fluid incommunication with the formation.
 4. The method of claim 1, wherein thedrilling fluid pressure at the formation is lower than the formationfluid pressure.
 5. The method of claim 1, wherein the formation is ahydrocarbon-bearing formation.
 6. The method of claim 1, wherein thepressure of the fluid in the formation is determined by prior survey. 7.The method of claim 1, wherein energy is added to the drilling fluid atsaid location by at least one pump arrangement.
 8. The method of claim7, wherein the pump is driven by the fluid flowing through thedrillstring.
 9. The method of claim 7, wherein the pump is electricallypowered.
 10. The method of claim 7, wherein the pump is driven by therotation of the drill string.
 11. The method of claim 1, wherein aproportion of the circulating drilling fluid flows directly from thedrill string bore to the annulus above said location.
 12. The method ofclaim 1, further comprising isolating sections at least one of the drillstring bore and annulus when there is no fluid circulation, such thatsuch sections may be maintained at relatively low pressures.
 13. Themethod of claim 1, wherein the pressure of the circulating drillingfluid at the formation is lower than hydrostatic pressure.
 14. Themethod of claim 1, further comprising agitating drill cuttings in theannulus.
 15. The method of claim 14, wherein the drill cuttings areagitated by agitating members driven by the flow of drilling fluidthrough the string.
 16. The apparatus of claim 1, further comprisingmeans for agitating cuttings in the annulus.
 17. The apparatus of claim16, wherein the agitating means is mounted on a body which is rotatablerelative to the drillstring and is driven to rotate by the flow ofdrilling fluid through the string.
 18. The method of claim 1, furthercomprising adding energy to the drilling fluid in the wellbore at asecond location above the formation.
 19. Drilling apparatus foraccessing a sub-surface formation containing fluid at a predeterminedpressure, the apparatus comprising: a drill bit mounted on a tubulardrill string for extending through a bore and drilling through aformation containing fluid at a predetermined pressure; means forcirculating drilling fluid down through the drill string to exit thestring at or adjacent the bit and enter an annulus between the stringand bore wall, and then continuously upwards through an the annulusbetween the string and bore wall; and means for adding energy to thedrilling fluid in the annulus above the formation such that the pressureof the drilling fluid above said means is higher than the pressure ofthe drilling fluid below said means and there is a predetermineddifferential between the pressure of the formation fluid and thepressure of the drilling fluid in communication with the formation. 20.The apparatus of claim 19, wherein said means for adding energy is atleast one pump arrangement mounted on the drill string.
 21. Theapparatus of claim 20, wherein the pump is adapted to be driven by thefluid flowing through the drill string.
 22. The apparatus of claim 21,wherein the pump comprises a turbine drive.
 23. The apparatus of claim20, wherein the pump is an electrically driven pump.
 24. The apparatusof claim 20, wherein the pump is adapted to be driven by rotation of thedrillstring.
 25. The apparatus of claim 19, wherein the drillstringincludes means for directing a proportion of the circulating drillingfluid directly from the drillstring bore to the annulus above saidenergy adding means.
 26. The apparatus of claim 25, wherein said meansfor directing a proportion of the circulating drilling fluid directlyfrom the drillstring bore to the annulus above said energy adding meansis a bypass tool.
 27. The apparatus of claim 19, further comprisingmeans for isolating sections of at least one of the drillstring bore andannulus when there is no fluid circulation.
 28. The apparatus of claim27, wherein the isolating means comprises at least one valve.
 29. Theapparatus of claim 19, wherein said means for adding energy comprise aplurality of pump arrangements mounted on a plurality of positions onthe drill string.
 30. The apparatus of claim 19, wherein the fluid flowup the annulus is, substantially unidirectional.
 31. A method ofreducing an effective circulating density pressure of a fluid in awellbore, the wellbore having at any depth a pore pressure, acirculating density fluid pressure higher than the pore pressure and afracture pressure higher than the circulating density pressure, themethod comprising: adding energy to the fluid at some predetermined,optimal location along the length of the wellbore, whereby thedifference between the fracture pressure and the effective circulatingdensity pressure is increased while the effective circulating densitypressure remains higher than the pore pressure; and wherein the optimallocation is a location along the wellbore at which the circulatingdensity pressure approaches, but is below the fracture pressure.
 32. Themethod of claim 31, wherein the energy is added with a pump having animpeller on an outer-surface thereof, the impeller in communication withfluid in an annulus defined between the wellbore and the tubular string;whereby the impeller provides a lifting energy to the fluid in theannulus and reduces the pressure of fluid in the wellbore therebelow.33. The method of claim 31, wherein the energy is added with a flowdiversion device that redirects flow of fluid from the interior of thetubing string to an annular area therearound.
 34. The method of claim31, wherein the circulating density pressure at any point in thewellbore is the sum of a hydrostatic pressure of wellbore fluid and afriction pressure brought about by the circulation of the fluid in thewellbore.
 35. A wellbore system for decreasing a circulating pressure offluid in the wellbore, the system comprising: a pore pressure thatgenerally increases as the depth of the wellbore increases; a wellborefluid pressure that is greater than the pore pressure and generallyincreases as the depth of the wellbore increases; an effectivecirculating density pressure that is greater than the wellbore fluidpressure and generally increases as the depth of the wellbore increases,the difference between the circulating density and the fluid pressuredefining a friction head; a fracture pressure that is greater than thecirculating density pressure and generally increases as the depth of thewellbore increases; and a pressure decreasing device in a tubularstring, a spaced distance from the bottom of the wellbore, the devicelocated at a position proximate the wellbore where the effectivecirculating density approaches the fracture pressure and wherein thedevice substantially reduces the friction head and thereby increase thedifference between the circulating density pressure and the fracturepressure.
 36. A method of reducing the pressure of fluid in a wellbore,the method comprising: placing a tubular string in the wellbore, therebycreating an annulus between the string and walls of the wellbore;circulating a fluid down the string and upwards in the annulus;utilizing the fluid in the string to operate a fluid driven, downholepump disposed in the string, the pump having an impeller on an outersurface thereof, the impeller in communication with the fluid in theannulus; whereby the impeller provides a lifting energy to the fluid inthe annulus and reduces the pressure of fluid in the wellboretherebelow.
 37. A method of reducing circulating density in a wellboreby communicating fluid between a device in a tubing string and anannulus around the string, comprising: directing a first portion of afluid flow from a first location in the string into the annulus in orderto reduce a fluid pressure in the annulus; and directing a secondportion of the fluid flow from a second location in the string into theannulus to reduced the pressure in the annulus, wherein the secondlocation is at an axially spaced distance from the first location.
 38. Amethod of reducing an effective circulating density pressure of a fluidin a wellbore in an underbalanced drilling operation wellbore, thewellbore having at any depth a pore pressure and a circulating densityfluid pressure lower than the pore pressure, the method comprising:adding energy to the fluid at a substantially vertical location alongthe length of the wellbore; and adding energy to the fluid at anon-vertical location alone the length of the wellbore, whereby thedifference between the pore pressure and the effective circulatingdensity pressure is increased, thereby maintaining the wellbore in anunderbalanced condition.
 39. A method of reducing a likelihood ofdifferential sticking in a wellbore comprising: adding energy to acirculating fluid in the wellbore at a location proximate a surroundingformation wherein the circulating density pressure approaches butremains below the formation pressure in order to decrease an effectivecirculating density pressure of the fluid to a level below the pressureof the formation.
 40. A method of adjusting a relationship between afluid circulating in a wellbore and a fracture pressure of a formationadjacent the wellbore, the method comprising: adding energy to thecirculating fluid at a predetermined location in the wellbore, wherein acirculating fluid pressure approaches, but is less than the fracturepressure, thereby increasing the difference in fluid and fracturepressures.
 41. A method of adjusting a pressure of a circulating fluidin a wellbore relative to a pressure in a formation of interest adjacentthe wellbore, comprising: drilling in the formation of interest; addingenergy to the circulating fluid at a predetermined location in thewellbore above the formation, thereby increasing a difference in thepressure of the circulating fluid and the pressure in the formation ofinterest.
 42. The method of claim 41, wherein the formation of interestis a hydrocarbon bearing formation.
 43. A method of increasing thelength of a drilled interval in a wellbore, comprising: adding energy tocirculating fluid in the wellbore at a predetermined location above aformation of interest, thereby increasing a difference in the pressureof the circulating fluid and the pressure in the adjacent formation ofinterest.
 44. Drilling apparatus for accessing a sub-surface formationcontaining fluid at a predetermined pressure, the apparatus comprising:a drill bit mounted on a tubular drill string for extending through abore and drilling through a formation containing fluid at apredetermined pressure; means for circulating drilling fluid downthrough the drill string to exit the string at or adjacent the bit, andthen upwards through an annulus between the string and bore wall; meansfor adding energy to the drilling fluid in the annulus above theformation such that the pressure of the drilling fluid above said meansis higher than the pressure of the drilling fluid below said means andthere is a predetermined differential between the pressure of theformation fluid and the pressure of the drilling fluid in communicationwith the formation; and means for agitating cuttings in the annulus,wherein the agitating means is mounted on a body which is rotatablerelative to the drill string and is driven to rotate by the flow ofdrilling fluid through the drill string.
 45. The method of claim 44,wherein one of the locations is a location along a substantiallyvertical portion of the wellbore and the other location is a locationalong a non-vertical portion of the wellbore.
 46. A method of reducingan effective circulating density pressure of a fluid in a wellbore, thewellbore having at any depth a pore pressure, a circulating densityfluid pressure higher than the pore pressure and a fracture pressurehigher than the circulating density pressure, the method comprising:adding energy to the fluid at some predetermined, optimal location alongthe length of the wellbore, whereby the difference between the fracturepressure and the effective circulating density pressure is increasedwhile the effective circulating density pressure remains higher than thepore pressure, and wherein the energy is added with a pump having animpeller on an outer surface thereof, the impeller in communication withfluid in an annulus defined between the wellbore and the tubular string.47. A method of reducing a likelihood of differential sticking in awellbore comprising: adding energy to a circulating fluid in thewellbore at a location above a formation in order to decrease aneffective circulating density pressure of the fluid to a level below thepressure of the formation.
 48. A method of reducing an effectivecirculating density pressure of a fluid in a wellbore, the wellborehaving at any depth a pore pressure, a circulating density fluidpressure higher than the pore pressure and a fracture pressure higherthan the circulating density pressure, the method comprising: addingenergy to the fluid at a first location along a length of the wellbore;adding energy to the fluid at a second location above the firstlocation, whereby the difference between the fracture pressure and theeffective circulating density pressure is increased while the effectivecirculating density pressure remains higher than the pore pressure. 49.A system for reducing an effective circulating density pressure of afluid in a wellbore, the wellbore having at any depth a pore pressure, acirculating density fluid pressure higher than the pore pressure and afracture pressure higher than the circulating density pressure,comprising: a plurality of apparatus located along a length of thewellbore for adding energy to the fluid in the wellbore, whereby thedifference between the fracture pressure and the effective circulatingdensity pressure is increased while the effective circulating densitypressure remains higher than the pore pressure.
 50. The system of claim49, wherein the plurality of apparatus comprises a first apparatuslocated at a first position in the wellbore and a second apparatuslocated at a position above the first apparatus.
 51. The system of claim50, wherein the first apparatus in located in a non-vertical portion ofthe wellbore and the second apparatus is located at a substantiallyvertical portion of the wellbore.
 52. The system of claim 49, wherein atleast one of the plurality of apparatus for adding energy comprises apump having an impeller.
 53. A drilling method in which a drill bit ismounted on a tubular drill string extending through a bore, the methodcomprising: drilling the bore extending through a formation containingfluid at a predetermined pressure; circulating drilling fluid downthrough the drill string to exit the string at the drill bit, whereinthe drilling fluid is circulated continuously up an annulus defined bythe bore and the drill string after exiting the drill bit; and addingenergy to the drilling fluid in the annulus at a location in the boresuch that the pressure of the drilling fluid above said location ishigher than the pressure of the drilling fluid below said location andthere is a predetermined differential between the pressure of theformation fluid and the pressure of the drilling fluid in communicationwith the formation.
 54. A drilling method in which a drill bit ismounted on a tubular drill string extending through a bore, the methodcomprising: drilling the bore extending through a formation containingfluid at a predetermined pressure; circulating drilling fluid downthrough the drill string to exit the string at a lower end thereof,wherein the drilling fluid is circulated up an annulus defined by thebore and the drill string; and adding energy to the drilling fluid inthe annulus at a location in the bore where a circulating densitypressure approaches, but is below a fracture pressure proximate thelocation.
 55. A drilling method in which a drill bit is mounted on atubular drill string extending through a bore, the method comprising:drilling the bore extending through a formation containing fluid at apredetermined pressure; circulating drilling fluid down through thedrill string to exit the string at the drill bit, wherein the drillingfluid is circulated continuously up a flow path defined by the bore andthe drill string after exiting the drill bit; and adding energy to thedrilling fluid at a location in the flow path such that the pressure ofthe drilling fluid above said location is higher than the pressure ofthe drilling fluid below said location and there is a predetermineddifferential between the pressure of the formation fluid and thepressure of the drilling fluid in communication with the formation.